Conventional Fracturing Research Articles

PROSPECTS OF SEARCHES AND PROBLEMS OF GAS DEVELOPMENT OF SEALED COLLECTORS OF THE DNIPRO-DONETSK DEPRESSION

The article considers the current problem of the hydrocarbon base of Ukraine. Materials that can serve as prerequisites for exploration and further development of gas from compacted reservoirs on the territory of the Dnieper-Donetsk graben are analyzed. In this article, the main parameters, that indicate the presence of gas in compacted reservoirs, are briefly considered. The data contain information about the features of the sedimentary section of the Paleozoic complex, namely, the geological structure of promising areas, the degree of catagenesis of gas-bearing rocks, the content of organic carbon in parent rocks, reservoir properties, and depths of gas-promising intervals. These data, taken from the results of drilling numerous wells, indicate a high probability of successful exploration for central basin gas within the axial zone of the Dnieper-Donetsk basin. As such deposits are difficult to extract, due to the complex geological structure of promising areas, a wide range of depths and, above all, poor reservoir properties of rocks containing gas, its development is impossible without the use of intensification methods. There are many chemical, thermal, mechanical technologies to cause the inflow of fluid from the reservoir, among which the hydraulic fracturing of the reservoir has become widespread. Modern methods of intensification are quite effective, but still remain imperfect, and therefore, there are some defects that cause certain complications in the development of the deposit. Тo cause the inflow of hydrocarbons from the compacted reservoirs, a foam gap of the formation is indicated, the use of which, in the opinion of the authors, is appropriate for deposits of this type. The article also points out the advantages of using a foam system compared to conventional fracturing and the need to improve some indicators of the foam system to its further use for compacted terrigenous reservoirs of the Dnieper-Donetsk avlakogen.

The enhancement of performance and imbibition effect of slickwater-based fracturing fluid by using MoS2 nanosheets

Slickwater-based fracturing fluid has recently garnered significant attention as the major fluid for volumetric fracturing; however, lots of challenges and limitations such as low viscosity, poor salt tolerance, and possible formation damage hinder the application of the conventional simple slickwater-based fracturing fluid. In addition, nanomaterials have proven to be potential solutions or improvements to a number of challenges associated with the slickwater. In this paper, molybdenum disulfide (MoS2) nanosheets were chemically synthesized by hydrothermal method and applied to improve the performance of conventional slickwater-based fracturing fluid. Firstly, the microstructure characteristics and crystal type of the MoS2 nanosheets were analyzed by SEM, EDS, TEM, XPS, and Raman spectroscopy techniques. Then, a series of evaluation experiments were carried out to compare the performance of MoS2 nanosheet-modified slickwater with the conventional slickwater, including rheology, drag reduction, and sand suspension. Finally, the enhanced imbibition capacity and potential mechanism of the nanosheet-modified slickwater were systematically investigated. The results showed that the self-synthesized MoS2 nanosheets displayed a distinct ultrathin flake-like morphology and a lateral size in the range of tens of nanometers. In the nano-composites, each MoS2 nanosheet plays the role of cross-linking point, so as to make the spatial structure of the entire system more compact. Moreover, nanosheet-modified slickwater demonstrates more excellent properties in rheology, drag reduction, and sand suspension. The nanosheet-modified slickwater has a higher apparent viscosity after shearing 120 min under 90 °C and 170 s−1. The maximum drag reduction rate achieved 76.3% at 20 °C, and the sand settling time of proppants with different mesh in the nano-composites was prolonged. Spontaneous imbibition experiments showed that the gel-breaking fluid of nanosheet-modified slickwater exhibited excellent capability of oil-detaching, and increase the oil recovery to ∼35.43%. By observing and analyzing the interfacial behavior of MoS2 nanosheets under stimulated reservoir conditions, it was found that the presence of an interfacial tension gradient and the formation of a climbing film may play an essential role in the spontaneous imbibition mechanism. This work innovatively uses two-dimensional MoS2 nanosheets to modify regular slickwater and confirms the feasibility of flake-like nanomaterials to improve the performance of slickwater. The study also reveals the underlying mechanism of enhanced imbibition efficiency of the nano-composites.

Study of clay stabilization mechanism and adsorption behavior of organic ammonium salts with low molar weight

Low-permeability sandstone reservoirs with low clay content are prone to water-sensitive damage during the fracturing process. In field applications, serious formation damage occurred with the conventional fracturing fluid system using KCl clay stabilizer. The introduction of SP clay stabilizer into the fracturing fluid formulation system significantly reduced the water-sensitive damage during fracturing and improved the reservoir transformation and production enhancement effect. In this paper, the clay stabilization mechanism of two substances, inorganic clay stabilizer KCl and organic ammonium salts with low molar weight SP, is studied by tests of swelling inhibition, ζ-potential test, and scanning electron microscope test to compare. On this basis, the adsorption behavior of SP on the surface of clay minerals is also studied in depth by isothermal adsorption and desorption experiments to explain mechanistically the difference of two different clay stabilizers on the fracturing effect, which helps to solve the formation damage problem in the fracturing and production enhancement process of low-permeability sandstone reservoirs with low clay content.

Fundamental study and utilization on supercritical CO2 fracturing developing unconventional resources: Current status, challenge and future perspectives

Under the fact that considerable exploration and production of unconventional resources and worsening global climate, reducing carbon emission and rationally utilizing carbon resources have been drawn increasing attention. Supercritical CO2 (SC-CO2) has been proposed as anhydrous fracturing fluid to develop unconventional reservoirs, since its advantages of reducing water consumption, reservoir contamination etc. Well understanding of SC-CO2 fracturing mechanism and key influencing factors will exert significant impact on the application of this technology in the field. In this paper, the fundamental studies on SC-CO2 fracturing from the aspects of laboratory experiment and simulation are reviewed. The fracturing experimental setups, fracture monitoring and characterizing methods, unconventional formation categories, numerical simulation approaches, fracturing mechanism and field application etc., are analyzed. The fundamental study results indicate that compared with conventional hydraulic fracturing, SC-CO2 fracturing can reduce fracture initiation pressure and easily induce complex fracture networks with multiple branches. The field test further verifies the application prospect and the possibility of carbon storage. However, due to the limitation of reservoir complexity and attributes of SC-CO2, massive challenges will be encountered in SC-CO2 fracturing. According to the current research status, the limitations in basic research and field application are summarized, and the future development direction of this technology and relevant suggestions are proposed.

Numerical Simulations of Radial Well Assisted Deflagration Fracturing Based on the Smoothed Particle Hydrodynamics Method

The technology of radial-well-assisted hydraulic fracturing is applied in the stimulation of low-permeability hydrocarbon reservoirs where commercial production cannot be achieved by the conventional fracturing method. Here, a study on the reservoir stimulation effect and the fracture propagation pattern of radial-well-assisted deflagration fracturing was carried out. Based on smooth particle hydrodynamics (SPH), rock mechanics theory, and finite element theory, a numerical model of radial-well-assisted deflagration fracturing was established by integrating the JWL state equation. Research on the effects of the deflagration position, radial well azimuth and horizontal principal stress difference on the fracture propagation was carried out. The results show that the deflagration position, radial well azimuth and horizontal principal stress difference have significant effects on the fracture area in deflagration fracturing. The closer distance from the deflagration position is, the larger the radial well azimuth and the smaller the horizontal stress difference are, leading to a larger fracture area, which is conducive to reservoir stimulation. During fracturing, both shear fractures and tensile fractures are formed. The formation and conversion of shear fractures and tensile fractures are related to the deflagration position, radial well azimuth, horizontal principal stress difference, etc.

Synthesis and Characterization of a Novel Self-Generated Proppant Fracturing Fluid System

Hydraulic fracturing is an important technology for the stimulation of oil and gas reservoirs. Conventional fracturing technology based on “sand-carrying” faces some challenges such as sand plugs; incompatibility with the well completion method; damage to the reservoir caused by the incomplete gel-breaking of the fracturing fluid; solid proppants inefficiently turning the corner in complex fracture networks, and so on. In this paper, a novel self-generated proppant fracturing fluid system is proposed to solve the above problems caused by “sand-carrying”. The advantage of the fracturing fluid system is that in the whole process of fracturing, no solid proppants will be injected. The fracturing fluid itself will transform into solid proppants in the induced fractures under high temperatures to resist fracture closure stress. The fluid system consists of two kinds of liquids. One is the phase change liquid (PCL), which occurs as a liquid–solid phase change at high-formation temperatures to form a solid proppant. The other is the non-phase change liquid (NPCL), which controls the dispersity of the PCL in the two-phase fluid system. The main building block of the PCL is confirmed to be the bisphenol-A diglycidyl ether-type epoxy resin, whereas the NPCL is mainly composed of surfactants. The viscosity, phase-change temperature, and time of the fracturing fluid system are, respectively, about 30 mPa·s, 80 °C, and 20 min.

Experimental comparisons of different cryogenic fracturing methods on coals

Hydraulic fracturing using water-based fracturing fluids is widely used in coalbed methane (CBM) reservoir development. However, the stimulation efficiency of conventional hydraulic fracturing in CBM reservoir is low. Liquid nitrogen (LN2) cryogenic fracturing is one possible method to improve the stimulation efficiency. To test the feasibility of the LN2 cryogenic fracturing, laboratory fracturing tests were conducted to investigate the performances of different LN2 cryogenic fracturing methods in this paper. The breakdown pressure and fracture morphology of water fracturing, LN2 direct fracturing, LN2 freeze fracturing, LN2 freeze-thaw fracturing and LN2 compound fracturing were compared. And the mechanisms of different cryogenic fracturing techniques are revealed. The results demonstrate that thermal damage caused by LN2 freezing is the main reason for the complicated fracture pattern in cryogenic fracturing. LN2 freeze-thaw fracturing has the lowest breakdown pressure and can create the most complex fractures among these cryogenic fracturing methods due to the huge thermal damage. LN2 freeze fracturing has the highest breakdown pressure. Because the thermal damage cracks and natural fractures in frozen rock are in freezing shrinkage, which activation are difficult. LN2 compound fracturing is the most potential technologies, which can produce more complex fracture networks than water fracturing and LN2 fracturing.

Stimulation mechanism and model establishment of enhanced imbibition oil recovery for A nano fracturing fluid

Chang 7 shale reservoir of Ordos Basin has characteristics of low porosity, ultra-low permeability, and low formation pressure coefficient. After hydraulic fracturing, the production of shale oil declines rapidly, and it has no solutions to replenish the formation energy. Currently, a nano variable-viscosity slickwater (named: NSI) is being used in the field for fracturing production. Compared with conventional fracturing fluid systems, the NSI system can increase production of oil wells by more than 4 times, and its economic benefits are very remarkable. The lab experiment shows that NSI system after the gel breaking has ability of enhanced imbibition oil recovery (EIOR), which may be an important stimulation mechanism of the NSI system. However, the contribution of EIOR to oil production is still unclear, and the corresponding mechanism and model are still lacking. Therefore, the fracturing parameters of Changqing Chang 7 reservoir were firstly optimized without considering the imbibition, and two wells were used to carry out field experiments with NSI and conventional slickwater. Then, commercial software is used to predict oil production. It was found that the actual production was higher than the predicted production. To explain this phenomenon, the effect of imbibition on enhanced oil recovery was investigated experimentally under reservoir temperature and pressure. The NMR T2 spectrum was quantitatively analyzed to clarify the variation of oil and water distribution in different pores of core. The results showed that capillary force was dominant in the small pores of core, and small pores were the main positions of EIOR. Water film was formed in large pores, which increases the migration resistance of the liquid, and allowed gravity to play an obvious role. Finally, based on the modified Aronofsky index model, an EIOR model suitable for the Changqing Chang 7 reservoir was proposed, which achieved a better match between actual production and simulated production of horizontal wells.

An advanced hydraulic fracturing technique: Pressure propagation and attenuation mechanism of step rectangular pulse hydraulic fracturing

AbstractHydraulic fracturing technology has played a pivotal role as a key technology in shale gas development, but the geological environmental problems caused have been worrying the public. This paper proposes an advanced step rectangular pulse hydraulic fracturing technique, which can achieve higher pressure and more complex fractures by pumping lower energy fluid. The results indicate that the pressure propagation of step rectangular pulse hydraulic fracturing can be divided into stable and unstable propagation stages. Compared with conventional hydraulic fracturing, longer unsteady propagation time, higher pressure and more complex pressure distribution can be obtained. Step pulse parameters are discussed. We found that the pulse pressure increases linearly with the increase in pulse amplitude. There are optimal pulse frequencies and comprehensive damping coefficients to get optimal fluid pressure in different shale reservoirs. These research results will help reduce geological environmental hazards, and can also provide guidance for the optimization of step rectangular pulse hydraulic fracturing technology in shale reservoirs.

Effect of loading rate and time delay on the tangent modulus method (TMM) in coal and coal measured rocks

Non-destructive techniques of in-situ stress measurement from oriented cored rocks have great potential to be developed as a cost cost-effective and reliable alternative to the conventional overcoring and hydraulic fracturing methods. The tangent modulus method (TMM) is one such technique that can be applied to oriented cored rocks to measure in-situ stresses. Like the deformation rate analysis (DRA), the rock specimen is subjected to two cycles of uniaxial compression and the stress-tangent modulus curve for the two cycles is obtained from the stress–strain curve. A bending point in the tangent modulus curve of the first cycle is observed, separating it from the tangent modulus curve of the second cycle. The point of separation between the two curves is assumed to be the previously applied maximum stress. A number of experiments were conducted on coal and coal measured rocks (sandstone and limestone) to understand the effect of loading conditions and the time delay. The specimens were preloaded, and cyclic compressions were applied under three different modes of loading, four different strain rates, and time delays of up to one week. The bending point in the stress-tangent modulus curves occurred approximately at the applied pre-stress levels under all three loading modes, and no effect of loading rate was observed on the bending points in TMM. However, a clear effect of time delay was observed on the TMM, contradicting the DRA results. This could be due to the sensitivity of TMM and the range of its applicability, all of which need further investigation for the in-situ stress measurement.

Experimental research on fracture initiation pressure of conventional triaxial slurry fracturing in similar material of sandy mudstone

Experimental research on fracture initiation pressure of conventional triaxial slurry fracturing in similar material of sandy mudstone

Study on Enhancing Shale Oil Recovery by CO2 Pre-Pad Energized Fracturing in A83 Block, Ordos Basin

The Ordos Basin is rich in shale oil resources. The main targeted layers of blocks A83 and X233 are the Chang 7 member of the Yanchang Formation. Due to extremely low permeability, a fracturing technique was required to enhance oil recovery. However, after adopting the stimulated reservoir volume-fracturing technology, the post-fracturing production of the A83 block is significantly lower than that of the X233 block. For this problem, the dominating factors of productivity of the two blocks were analyzed using the Pearson correlation coefficient (PCC) and the Spearman rank correlation coefficient (SRCC), showing that the main reason for the lower production of the A83 block is its insufficient formation energy. To solve this problem, the CO2 pre-pad energized fracturing method was proposed. To study the feasibility of CO2 pre-pad energized fracturing in the A83 block, an integrated reservoir numerical simulation model of well A83-1 was established based on the idea of integration of geology and engineering. Additionally, the productions within five years after conventional volume fracturing and CO2 pre-pad energized fracturing were compared. The results show that compared with conventional volume fracturing, the cumulative oil production of CO2 pre-pad energized fracturing increases by 11.8%, and the water cut decreases by 16.5%. The research results can guide the subsequent reservoir reconstruction operation in the A83 block and provide new ideas for fracturing in the future.

Experimental Study on the Hydraulic Fracture Propagation in Inter-Salt Shale Oil Reservoirs

In response to the difficulty of fracture modification in inter-salt shale reservoirs and the unknown pattern of hydraulic fracture expansion, corresponding physical model experiments were conducted to systematically study the effects of fracturing fluid viscosity, ground stress and pumping displacement on hydraulic fracture expansion, and the latest supercritical CO2 fracturing fluid was introduced. The test results show the following. (1) The hydraulic fractures turn and expand when they encounter the weak surface of the laminae. The fracture pressure gradually increases with the increase in fracturing fluid viscosity, while the fracture pressure of supercritical CO2 is the largest and the fracture width is significantly lower than the other two fracturing fluids due to the high permeability and poor sand-carrying property. (2) Compared with the other two conventional fracturing fluids, under the condition of supercritical CO2 fracturing fluid, the increase in ground stress leads to the increase in inter-salt. (3) Compared with the other two conventional fracturing fluids, under the conditions of supercritical CO2 fracturing fluid, the fracture toughness of shale increases, the fracture pressure increases, and the fracture network complexity decreases as well. (4) With the increase in pumping displacement, the fracture network complexity increases, while the increase in the displacement of supercritical CO2 due to high permeability leads to the rapid penetration of inter-salt shale hydraulic fractures to the surface of the specimen to form a pressure relief zone; it is difficult to create more fractures with the continued injection of the fracturing fluid, and the fracture network complexity decreases instead.

Optimization and performance evaluation of a novel anhydrous CO2 fracturing fluid

The conventional water-based fracturing fluids have such defects as large water consumption, serious environmental pollution and water-sensitive damage to reservoirs in the development of tight oil. In this study, a novel anhydrous CO2 fracturing fluid system was constructed with the compositions of 7 wt% polydimethylsiloxane (100 cs), 5 wt% ethanol and 88 wt% liquid CO2. The viscosity of the system could reach 6.52 mPa s, which was 37 times higher than that of pure liquid CO2 at −15 °C and 30 MPa. The pressure resistance, temperature resistance, anti-swelling property, filtration loss property, core damage property, corrosion property and wetting inversion property of anhydrous CO2 fracturing fluid were systematically evaluated by physical simulation experiments. The environmental scanning electron microscopy (ESEM) and mercury injection experiment were conducted. The viscosity retention rate of anhydrous CO2 fracturing fluid reaches 47.92% when the temperature increases by 50 °C. When the pressure increases by 25 MPa, the viscosity increases by 2.6 times. It ensures that the viscosity of anhydrous CO2 fracturing fluid is well retained after injection into the formation. In addition, the anti-swelling rate of anhydrous CO2 fracturing fluid reaches 90.91%. The filtration coefficient is reduced by 69.20%. For low permeability sandstone cores, the permeability damage rate is 18.80% and the porosity damage rate is 12.58%. After aging for 30 h, the permeability and porosity of core increased 39.23% and 5.52%, respectively. Meanwhile, the wettability of the core could be changed from hydrophilic to neutral, which reduced the flow resistance of the oil phase and improved tight oil recovery. Through this study, we hope to broaden the application of anhydrous CO2 fracturing fluids in tight oil development.

Development of gelled acid system in high-temperature carbonate reservoirs

Acid fracturing technology is an effective way to reconstruct carbonate reservoirs. However, considering the characteristics such as strong heterogeneity, deep burial, and high temperature, the conventional acid fracturing system cannot be used in the low-permeability area effectively. Aiming at resolving this problem, Tarim Oilfield was taken as the research object and a new high-temperature-resistant gelled acid system with modified xanthan gum was developed in the present study. Then the temperature resistance and acid resistance of the thickening agents were tested through experiments. Moreover, the conductivity of acid-etched fractures was studied. The acid flow in the fracture was simulated to study the deep penetration capacity of the acid system. The obtained results show that the gelled acid system has good temperature resistance, acid resistance, and shear resistance, and the viscosity of the acid system at 160 °C remains 21 mPa s. The acid pressure experiment with a developed gelled acid system shows that the acid pressure effect is significant at indoor high temperatures of 160 °C. At a confining pressure of 30 MPa, the acid-etched fracture has a conductivity of 9.39D•cm. It was found that as the experimental ambient temperature increases, the conductivity of acid etching fracture gradually increases and stabilizes at 9.5D•cm. Finally, a “pink-out” gradient reduction appears in the acid concentration of the fracture, and flows along the fracture to the deep part of the formation, and propagates the fracture. It is concluded that the proposed method can be applied to communicate with the reservoir to increase production and injection. This article is expected to provide a theoretical foundation for the exploration of high-temperature resistance xanthan gum in the field of acid compression.

Experimental study on deformation and fracture characteristics of coal under different true triaxial hydraulic fracture schemes

Hydraulic fracturing techniques are often applied to form permeability enhancement zones near boreholes and/or wellbores in tight low-permeability reservoirs to improve their extraction efficiency. As conventional hydraulic fracturing techniques often generate high breakdown pressure and induced seismic potential, novel alternative production enhancement techniques (such as pulse hydraulic pressurization) have been proposed. However, their applicability requires further verification. Therefore, this study conducted hydraulic fracturing tests of coal under three test schemes: conventional hydraulic fracturing (CHF), stepwise pressurization hydraulic fracturing (SPHF), and stepwise pulse pressurization hydraulic fracturing (SPPHF), considering the true triaxial stress state of an actual coal seam. The results showed that the breakdown pressure of coal decreased with an increase in the horizontal stress difference (σ2-σ3). Moreover, the pulse pressurization produced more intergranular fractures and caused a large number of particles to be conducted as a stress concentrator at the fracture tip spalling, which promoted the unstable propagation of fractures, which decreased the breakdown pressure of coal. The abnormally high breakdown pressure in the SPHF experiments is likely due to the obstruction of high σ2 to the fracture propagation rate and fluid injection, which intensifies the fluid hysteresis effect and the stable fracture development and expansion during the pressure-maintaining stage, thus increasing the breakdown pressure. To describe the relationship between the variation in the breakdown pressure and fracture evolution characteristics, we introduced the equivalent characteristic length l and established a breakdown pressure prediction model based on the tensile stress criterion, which shows effective prediction of the breakdown pressure in different test schemes. Anisotropic principal strain appeared under different injection schemes. During the CHF and SPHF experiments, fluid injection deformed the σ1 direction by compression and the σ3 direction by expansion. In the σ2 direction, the deformation transitioned from expansion at a low stress level to compression at a high stress level. The deformation in the σ2 direction was always compressive in the SPPHF experiments. Continuous and pulse pressurizations can promote the deformation and fracture development. For the fracture morphology, the coal in the CHF experiments was dominated by a single tensile fracture, and macroscopic shear fractures were formed in the SPHF and SPPHF experiments owing to the continuous stimulation of fluid pressure to the bonding of particles and the weak surface structure, such as bedding and cleats during the pressure maintenance and pulse, and the fragmentation effect was significant and accompanied by obvious particle spalling.

Construction of sulfur-free gel breaker agent system and investigation on gel-breaking mechanism for association fracturing fluid

ABSTRACT Sulfur is usually contained in existing gel breaker systems for fracturing fluids, which leads to the generation of hydrogen sulfide gas. In the process of fracturing development. The presence of hydrogen sulfide gas would cause equipment corrosion and environmental pollution. In this paper, a system of sulfur-free gel breaker agents for association fracturing fluid was constructed by evaluating the gel-forming and breaking properties of the fracturing fluid applied with this formula. The results showed that the combinations of 0.02% chlorine dioxide and 0.12% to 0.2% citric acid were chosen as the sulfur-free gel breaker formulas at 80 to 100°C. The polymer molecular chains were broken by synergistic effects of low concentration chlorine dioxide and citric acid to reduce the viscosity of association fracturing fluid, achieving gel-breaking. Simultaneously, the influence of hydrogen sulfide on the development process could be inhibited through bactericidal and oxidation actions of chlorine dioxide. The viscosity of the sulfur-free fracturing fluid remains above 50 mPa·s within 60 minutes, the value of the flow regime index was between 0.2593 and 0.3125, and the settling rate in this system was 0.024 to 0.042 mm/s. The temperature resistance, shear resistance, rheological properties, and sand carrying capacity of the sulfur-free fracturing fluid were not inferior to that of the conventional fracturing fluids, which guaranteed the effect of fracturing reformation. This study is of great significance to not only the development of environmental-friendly fracturing fluid but also the prevention and control of toxic and harmful gases, promoting sustainable development of oilfields.

The spontaneous imbibition mechanisms for enhanced oil recovery by gel breaking fluid of clean fracturing fluid

The quick flowback treatment after conventional fracturing construction can waste a lot of energy from fracturing fluid. Meanwhile, spontaneous imbibition has great application potential for enhanced oil recovery (EOR). In this work, based on pre-developed silica nanoparticle-reinforced CO2-sensitive fracturing fluid system, the imbibition factors of the gel breaking fluid were studied. In addition, the HNMR technology, AFM, contact angle test, and interfacial tension (IFT) test were used to explore the mechanism of spontaneous imbibition. The results show that imbibition mainly occurs in the small pores, and the adsorption of components can reduce roughness and flow resistance. Meanwhile, the adsorption layer was formed by surfactants and nanoparticles, changing wettability from oil-wet to water-wet, reducing the IFT between oil and water. The synergistic effect of multi-component improves the imbibition effect. We expect that this study can broaden the application of multi-component gel breaking fluid in low permeability reservoirs.

Development and Consideration of 3D Transient Electromagnetic Forward Modelling for the Hydraulic Fracturing Monitoring

Hydraulic fracturing monitoring is an essential technical means for unconventional oil and gas development. Hydraulic fracturing monitoring can be applied to evaluate the degree of development and scale of fractures in target reservoirs and to diagnose the extent of fracturing fluid. It can then be used to estimate the stimulated reservoir volume (SRV). Therefore, it is critical to forecast reservoir yields and unconventional oil and gas resource utilization. Conventional hydraulic fracturing monitoring is predominantly based on microseismic monitoring, which can effectively delineate the range and main direction of the fracturing fractures. However, microseismic fractures is difficult to guarantee that the volume of fracturing in the seismically active fractures is equal to that in the fracturing reservoirs. Recently, the transient electromagnetic (TEM) based on the substantial conductivity difference between the fracturing fluid and the background earth has been used as an emerging technology in the field of fracturing monitoring. It can then be used to evaluate the degree of fracturing development quantitatively. Based on the background of using TEM in Hydraulic fracturing monitoring, this paper gives a short review of 3D forward TEM modelling developments and its applications for hydraulic fracturing monitoring. And the challenges of 3D forward modelling for hydraulic fracturing monitoring application have been discussed. We found that current TEM forward modeling algorithm should meet the challenges of considering fracturing medium, anisotropy and using a multi-scale forward method. Solving these technical difficulties will promote hydraulic fracturing monitoring technology for unconventional oil and gas exploration.

Numerical Simulation of Rock Breaking by High-Temperature and High-Pressure Water under Thermal Driving

To solve the difficult problems in the field of unconventional oil and gas extraction and hard rock excavation in urban underground spaces, this paper proposes a rock-breaking technique with high-temperature and high-pressure water under thermally driven conditions and establishes a coupled thermal-fluid-solid model with COMSOL Multiphysics (COMSOL Co., Ltd. Shanghai, China). Different simulation groups are established by controlling variables to explore the effects of the surrounding rock load, heat source power, and Biot coefficient on the damage evolution during thermally driven rock breaking. To make the results relevant to practical engineering, the damage evolution results under the maximum normal stress criterion, maximum normal strain criterion, and Coulomb-Navier damage criterion are considered, and a comparative analysis is performed. The results of this study show that an increase in unilateral load and heat source power accelerates the damage evolution rate, while an increase in bilateral load and Biot coefficient has the opposite effect. The damage evolution rate controlled by the maximum normal stress criterion is the fastest under general conditions. Finally, the advantages in rock breaking provided by the established method are verified by a comparison of results from the proposed model and a conventional hydraulic fracturing model.